Redundancy enhanced removal of pressure-effect offset for drill bit strain gauge measurements

ABSTRACT

As a wellbore is extended into a formation, hydrostatic and hydrodynamic pressures change due to variations in drilling mud weight, fluid density, etc. Strain gauges downhole measure forces experienced by drilling equipment also experience strain due to hydrostatic and hydrodynamic pressures. In order to measure strain due to drilling, hydrostatic and hydrodynamic pressure contributions are removed from strain measurement by removal of a pressure-effect offset, which zeroes or tares the strain measurements. Values of the pressure-effect offset can also be monitored to check that strain measurements are accurately zeroed or to monitor wellbore operations and conditions.

BACKGROUND

The disclosure generally relates generally to earth drilling includingmining and earth drilling, e.g., deep drilling, for obtaining oil, gas,water, soluble or meltable materials or a slurry of minerals from wells,and more specifically to drill bit strain measurements.

BACKGROUND

Drillstrings and drill bits in a wellbore experience hydrostaticpressure—as a result of drilling fluid density and gravitationalforces—and hydrodynamic pressure—as a result of drilling fluidcirculation and movement. Pressure is a measure of force per unit area,where such forces can cause strain and deformation of the drillstringand drill bit. Drillstrings and drill bits also experience drillingforces as a result of interaction between the drill bit, drillstring,and formation. The total force experienced can be determined based onthe one or more measurement of strain experienced by the drillstringand/or drill bit.

BRIEF DESCRIPTION OF THE DRAWINGS

Aspects of the disclosure may be better understood by referencing theaccompanying drawings.

FIG. 1 depicts an example system for determining a pressure-effectoffset for strain measurements obtained at a location on a drillstring.

FIG. 2 depicts a flowchart of example operations for determining ahydrostatic pressure-effect offset based on strain measurements.

FIG. 3 depicts a flowchart of example operations for determining ahydrodynamic pressure-effect offset based on strain measurements.

FIG. 4 depicts a flowchart of example operations for checking for errorin the hydrostatic pressure-effect offset.

FIG. 5 depicts a flowchart of example operations for checking for errorin the hydrodynamic pressure-effect offset.

FIGS. 6A, 6B, and 6C depict graphs corresponding to tared strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit during addition of a stand.

FIGS. 7A, 7B, 7C, and 7D depict graphs corresponding to strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit during addition of a stand.

FIGS. 8A, 8B, 8C, and 8D depict graphs corresponding to strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit for multiple stand additions during drilling.

FIG. 9 depicts a schematic diagram of an example drilling system.

FIG. 10 depicts an example computer system with a pressure-effect offsetcalculator and a pressure-effect based strain error checker.

DESCRIPTION

The description that follows includes example systems, methods,techniques, and program flows that embody aspects of the disclosure.However, it is understood that this disclosure may be practiced withoutthese specific details. For instance, this disclosure refers to axialstrain in illustrative examples. Aspects of this disclosure can be alsoapplied to radial strain and circumferential strain. In other instances,well-known instruction instances, protocols, structures and techniqueshave not been shown in detail in order not to obfuscate the description.

Overview

Strain gauges downhole measure forces experienced by various types ofdrilling equipment (e.g., drill pipes, drill bits, etc.). As a wellboreis extended into a formation, hydrostatic and hydrodynamic pressureschange due to variations in drilling mud weight, fluid density, etc. Inorder to calculate drilling forces from strain measurements, thecontribution of pressure to the strain measurement is determined (orotherwise approximated) and subtracted or removed from the measurementsof strain. The hydrostatic and hydrodynamic pressure contributions tostrain measurements are calculated during off-bottom events (with andwithout fluid flow). During off-bottom events such as stand additions,other drilling forces are negligible, and one or more pressure-effectoffset can be calculated. The one or more pressure-effect offset is thenused to separate contributions of hydrostatic and hydrodynamic pressurefrom contributions to measurements of strain from other drilling forces.

Based on values of pressure-effect offsets calculated at various timesand/or points during a drilling run, accuracy of calculatedpressure-effect offsets is monitored and pressure-effect offsets can becorrected to provide accurate drilling force and strain information.Pressure-effect offset accuracy is checked by comparing multiple methodsor instances of pressure-effect offset determination or by comparing apressure-effect offset value or trend in value to a value or trend invalue expected for a wellbore trajectory and conditions.

Hydrostatic and hydrodynamic pressures, which contribute to thepressure-effect offset value, are estimable based on depth, inclination,mud weight, and flow rate data. When mud weight changes are accountedfor, hydrostatic pressure generally increases with vertical depth—as theweight of the drilling mud column increases. When mud weight and flowrate changes are accounted for, hydrodynamic pressure generally remainsconstant from drillpipe stand addition (i.e., addition of one or moredrillpipe sections) to drillpipe stand addition. Hydrostatic andhydrodynamic pressure-effect offset values correspond to pressuremagnitude and can be calculated for various drillpipe stands (“stands”)and checked for consistency during addition of a stand (“standaddition”) and for consistency between the end of a first stand and thebeginning of a second stand. Hydrostatic-pressure-effect offsets arealso checked with respect to inclination and depth measured in thewellbore, where inclination affects the rate at which hydrostaticpressure changes. Based on one or more of these methods, pressure-effectoffsets are checked qualitatively and/or quantitatively for accuracy andinaccurate values can be discarded. Checking pressure-effect offsetvalues for errors and inconsistencies over time increases robustness ofstrain gauge measurements and calibrations. As error-checkedpressure-effect offset is more robust, this likewise increasesrobustness of strain-measurement-based determination of forces appliedto components of the drill string (e.g., weight on bit (WOB), torque onbit (TOB), bit bending, etc.).

Example Illustrations

FIG. 1 depicts an example system for determining a pressure-effectoffset for strain measurements obtained at a location on a drillstring.FIG. 1 includes a schematic diagram of an example drilling apparatus100, a schematic diagram of a strain gauge 140, a schematic diagram of apressure-effect offset calculator 150, and schematic diagram of apressure-effect based strain error checker 180 (hereinafter “the errorchecker 180”).

Drilling of oil and gas wells is commonly carried out using a string ofdrill pipes connected together to form a drillstring 106 that can belowered through a rotary table into a wellbore 108. The drillstring 106may operate to penetrate the rotary table for drilling the wellbore 108through subsurface formations 110. The drillstring 106 may include akelly, drill pipe 112, and a bottom hole assembly (BHA) 114, perhapslocated at the lower portion of the drill pipe 112. The example drillingapparatus 100 may also include a drilling rig located at the surface 102of a well 104, where the drilling rig is not shown here for simplicity.

The BHA 114 may include drill collars 116, a down hole tool 118, and adrill bit 120. The drill bit 120 may operate to create a wellbore 108 bypenetrating the surface 102 and subsurface formations 110. The down holetool 118 may comprise any of a number of different types of toolsincluding a mud pump, MWD tools, LWD tools, and others. The drillstring106 also includes a strain gauge 132 and can include additional straingauges. The strain gauge 132 is depicted as proximate to the drill bit120 and located in the BHA 114, but it should be understood that thestrain gauge 132 can be disposed at any location on the drillstring106—such as outside the BHA 114, at the drill collar 116, internal to orexternal to the drillstring 106 between the drill collar 116 and the BHA114, within or associated with one or more down hole tool 118,integrated into the drill bit 120, including within a connection orshank of the drill bit 120. Only the strain gauge 132 is depicted, butmultiple strain gauges of the same or different types can be disposedalong the drillstring 106 and in different portions of the exampledrilling apparatus 100. The strain gauge 132 can include a processor andmemory or be in communication with a device with a processor and memory.

During drilling operations, a mud pump may pump drilling fluid(sometimes known by those of ordinary skill in the art as “drillingmud”) from a mud pit through a hose into the drill pipe and down to thedrill bit 120. The drilling fluid can flow out from the drill bit 120and be returned to the surface 102 through an annular area 122 betweenthe drill pipe 112 and the sides of the wellbore 108. The drilling fluidmay then be returned to the mud pit, where such fluid is filtered. Insome embodiments, the drilling fluid can be used to cool the drill bit120, as well as to provide lubrication for the drill bit 120 duringdrilling operations. Additionally, the drilling fluid may be used toremove subsurface formation 110 cuttings created by operating the drillbit 120. In some embodiments the drill bit 120, other elements of theBHA 114 (such as the down hole tool 118) or the strain gauge 132 cansend communications to a surface-based controller or operator viaelectronic, pressure (e.g., mud motor or mud pulse telemetry), optical,etc. means of communication.

During drilling operations, the drillstring 106 (perhaps including thekelly, the drill pipe 112, and the BHA 114) may be rotated by the rotarytable. In addition to, or alternatively, the BHA 114 or a portion of theBHA 114 may also be rotated by a motor (e.g., a mud motor) that islocated down hole. The drill collars 116 may be used to add weight tothe drill bit 120. The drill collars 116 may also operate to stiffen theBHA 114, allowing the BHA 114 to transfer the added weight to the drillbit 120, and in turn, to assist the drill bit 120 in penetrating thesurface 102 and subsurface formations 110.

The drill bit 120 can contact a bottom 124 (of a vertical wellbore) orlateral end (of a lateral wellbore) of the wellbore 108 in order toadvance the progress of the wellbore drilling. The efficiency ofdrilling and the forces on the drill bit 120 and the BHA 114 areaffected by the position of the drill bit 120 relative to the bottom 124of the wellbore 108. Depth of the drill bit 120 in the wellbore can bemeasured by the length of the drillstring 106 or other parameters at thesurface 102, but in cases where the drill bit 120 experiences vibrationsor non-idealities such as axial displacement, bending, stick-slip, etc.forces and loads transferred between the drill bit 120 and the bottom124 of the wellbore 108 can vary in magnitude during drilling and thedrill bit 120 can also experience fits and starts in rotationalmovement. The transfer of drilling energy from the drill bit 120 to aface of the wellbore 108 can be calculated based on measured forcesexperienced by the drill bit 120 or the drillstring 106. Weight on bit(WOB) is a measure of the force transferred axially to a terminus of thewellbore 108 and is traditionally measured in pounds (lbs) or thousandsof pounds (10001 b). Torque on bit (TOB) is a measure of the forcetransferred rotationally to a side or the terminus of the wellbore 108and is traditionally measured in pound feet (lb ft). Rotational velocityof the drill bit is measured in rotations per minute (RPM). WOB, TOB,and RPM can be inferred at the surface 102 from remote measurements,such as hook load, mud flow, etc., or can be measured directly at thedrill bit 120 or other locations on the drillstring 106 with embeddedforce measurement devices, such as the strain gauge 132.

The schematic diagram of the strain gauge 140 depicts the forces exertedon the drillstring 106 which are measured by the strain gauge 132 oranother example strain gauge. Pressure, which is a force per unit area,is exerted on the outside of a drillstring component as a function ofexternal pressure, flow rate and mud weight 142. Pressure is alsoexerted on the inside of the drillstring component as a function ofinternal pressure, flow rate, and mud weight 144. In the absence ofadditional axial and circumferential strain (i.e., strain caused by WOB)and additional torsional strain (i.e., strain caused by TOB),deformation of the drillstring component is a function of a net strain146, which is a function of both the internal pressure and externalpressure. In cases where no fluid is flowing through or around thedrillstring component and where internal pressure and external pressureare equal, the net strain 146 is a function of the hydrostatic pressure.In cases where fluid is flowing, the internal pressure and externalpressure are unequal and the net strain 146 is a function of thehydrodynamic pressure. Where the drillstring can be modelled as anelastic spring (i.e., in the linear displacement and proportional forceregime), strain in the absence of WOB and TOB can be converted to apressure—axial strain along the longitudinal axis of the drillstring,circumferential strain along the circumferential direction of thedrillstring, etc. In a cylindrical coordinate system for a drillstring,the axial, radial, and circumferential directions can be consideredorthogonal, where the circumferential direction can be generallytangential to a circumference of the drillstring and/or wellbore. Otherstrain models may also be used, where a relationship betweendisplacement, deformation, and force is well-defined.

Hydrostatic pressure is a function of the weight of the fluid columnpresent in the wellbore—where such weight is a function of the mass ordensity of the drilling mud (i.e., mud weight), height of the column offluid (i.e., depth of the well), and gravitational force direction(which depends on the lateral and horizontal orientation of the well).Hydrostatic pressure is therefore indicative of well depth, inclination,and mud weight and qualitative determinations of wellbore conditions aremade based on changes in hydrostatic pressure if multiple variables areunknown. If only one variable is unknown, it can be solved for using therelationship between hydrostatic pressure, mud weight, well depth, andinclination. As mud weight can change as a result of fluid influx orloss, and as well depth and inclination can vary from planned values orsensor determined values, hydrostatic pressure tracking via strain gaugemeasurements adds to downhole data collection. Hydrostatic pressure fora vertical fluid column can be calculated using Equation 1, below:

P=μgh  (1)

where P is pressure, ρ is fluid density, g is acceleration due togravity, and h is fluid depth or the height of the fluid column. Itshould be understood that hydrostatic pressure calculations change dueto applied pressure, wellbore inclination, fluid influx, etc. and thatappropriate relationships for hydrostatic pressure will vary byapplication and wellbore geometry. Because hydrostatic pressure is afunction of the weight of a fluid column, hydrostatic pressure variesdue to changes in values of fluid density (e.g., mud weight), depth(e.g., height of the fluid column), and wellbore inclination (where thegravitational force applied to a fluid column varies based on thedirection of the column with respect to gravity).

The hydrostatic pressure-effect offset can be related to hydrostaticpressure— the hydrostatic pressure-effect can be proportional tohydrostatic pressure but may also be related in another manner, such assub-linearly, exponentially, polynomially, etc. The value of thehydrostatic pressure-effect offset can therefore correspond to or beused for monitoring wellbore conditions and operations. For example,hydrostatic pressure is expected to increase linearly with depth in avertical wellbore. Deviations from a linear increase in the hydrostaticpressure-effect value as a function of depth can reflect changes in mudweight, wellbore deviation from the vertical, or errors in thehydrostatic pressure-effect calculation.

Hydrodynamic pressure is a function of drilling mud characteristics(e.g., mud weight, viscosity, density, diffusivity, etc.) and fluid flowrates. The hydrodynamic pressure-effect offset can be proportional to afactor representing a combined flow rate and mud weight. Thehydrodynamic pressure-effect offset can be proportional to thehydrodynamic pressure or may be related in another manner, such as thosedescribed for the hydrostatic pressure and hydrostatic pressure-effectoffset. In some embodiments, a single equation can describe therelationship between a pressure-effect offset or other strain gaugemeasurement and a pressure. In other embodiments, the relationship canbe described by various equations or different equations for certainstrain and/or pressure ranges. For example, small pressures can cause alinear change in the strain gauge measurements (i.e., a proportionalpressure-effect offset) while large pressures may cause a sublinear orsuper-linear change in the strain gauge measurements as the strain gaugeexperiences greater deformation. The relationship between pressure andpressure-effect offset can vary based on strain gauge type, strain gaugeorientation, strain gauge filament material, temperature, etc.

With additional surface data (such as average mud weight, drilling mudvolume, mud density as a function of pressure, fluid throughput rate,mud motor speed, etc.), flow rate and mud weight values can becalculated based on hydrodynamic pressure. During drilling, thecalculated flow rate and mud weight values are monitored and informcontrol and correction—where flow rates vary due to ball up, nozzleblockages, nozzles blow outs, etc. and mud weight varies due to fluidinflux and loss. For strain gauges in communication with a drillingcontroller, such as at the surface, determination of hydrostatic andhydrodynamic pressure allows and improves real-time (or quasi-real-timeor intermittent) trouble shooting for drill string components andcontrol and correction of drilling operations. Hydrodynamic pressure canbe calculated using Bernoulli's equations for incompressible flow, suchas Equation 2 (below) if the drilling mud is approximatelyincompressible:

$\begin{matrix}{{\frac{v^{2}}{2} + {{\mathcal{g}}z} + \frac{P}{\rho}} = {Constant}} & (2)\end{matrix}$

where v is the fluid flow velocity at a point on a streamline, z is theelevation of the point above a reference plane, and the constant is ofequal value for all points along a streamline. Other equations can beused to determine hydrodynamic pressure, including the Hagen-Poiseuilleequation for laminar flow and general diffusion equations derived fromon Fick's laws of diffusion. Appropriate hydrodynamic pressurecalculation will vary based on wellbore geometry and drillstringgeometry and flow characteristics including flow characteristicsencompassed by dimensionless numbers such as the Mach number, Reynoldsnumber, etc.

Because hydrodynamic pressure is a function of the viscosity, density,flow rate, flow regime, and wellbore and drillstring geometry (i.e.,tubular versus square), hydrodynamic pressure varies due to changes invalues of fluid density (e.g., mud weight), fluid viscosity (e.g., mudcomposition where oil-based muds and water-based muds can vary inviscosity), wellbore and drillstring geometry (i.e., clearance betweenwellbore and drillstring which can be effected by drill bit gauge and/orwellbore deterioration), fluid speed (e.g., flow rate), etc. Thehydrodynamic pressure-effect offset can therefore correspond to or beused for monitoring wellbore conditions and operations. For example,hydrodynamic pressure is expected to decrease as flow rate decreases andan unexpected decrease in the hydrodynamic pressure-effect offset cancorrespond to a decrease in flow rate caused by a loss in drilling mudcirculation (e.g., a loss of drilling mud to the formation) or errors inthe hydrodynamic pressure-effect offset calculation.

The pressure-effect offset calculator 150 operates on strainmeasurements obtained during a stand addition, component addition, orother pause in drilling. Drill pipe is added to the drillstring 106 insections, called stands, where drilling and mud flow are paused duringstand additions and the drillstring 106 is pulled off-bottom 128 of thewellbore 108. Drilling can be paused during the addition of each standor any drillstring or wellbore component. Drilling can also be paused toswitch or replace a drillstring, wellbore, or drilling rig componentwhere no component is actually added to the drillstring. Drilling mayalso be paused to take one or more measurements (i.e., magnetometer,accelerometer, directional measurements, etc.) or transmit data (forexample, nuclear magnetic resonance (NMR) data sets), where measurementscan coincide with stand additions but can also be triggeredindependently of stand additions—such as to acquire or transmit higherquality or resolution data. Hereinafter “stand addition” should beunderstood to also encompass any pause in drilling or other off-bottomevent during which WOB is substantially lower than during activedrilling and during which mud flow and mud motor or drill bit rotationmay or may not be paused, whether or not a stand or other component(e.g., drill collar, stabilizer, tool, etc.) is added to thedrillstring. During the stand addition, the WOB approaches a localminimum and the TOB and the RPM approach approximately or substantiallyzero. The pressure-effect offset calculator 150 can be located at thesurface 102 or at the drill bit 120 or at another location within thewellbore 108. The pressure-effect offset calculator 150 is incommunication with the strain gauge 132 or part of the strain gauge 132.The pressure-effect offset calculator 150 can operate in real time oroperate based on strain measurements collected during a drilling runafter the completion of the drilling run, such as when the strain gauge132 is tripped out or otherwise removed from the wellbore 108.

A graph 152 depicts strain measurements obtained during a drilling run,where WOB is at a minimum during stand additions. The graph 152 depictsportions of the drilling run where strain values 156 and strain values157 correspond to stand additions or other elements where drilling ispaused or otherwise in an off-bottom regime 158. The graph 152 alsodepicts portions of the drilling run where strain values 160 correspondto WOB for an on bottom drilling regime 162.

The strain measurements of the graph 152 can be axial strainmeasurements (i.e., measurements of strain along the longitudinal axisof the drillstring), can be radial or circumferential strainmeasurements (i.e., measurements of strain along the radial axis of thedrillstring or along the tangential direction of an outer radius of thedrillstring), or be can strain measurements for another axis or along acombination of axes. The strain measurements of the graph 152 can alsobe obtained from a strain gauge which can measure in more than onestrain direction or along more than one axis, either at the same time orbe moved to measure strain in different directions. Hereinafter “strainmeasurements” should be understood to encompass axial strainmeasurements, circumferential strain measurements, radial strainmeasurements, and combinations thereof.

The pressure-effect offset calculator 150 identifies the strain values156 and the strain values 157 corresponding to the off-bottom regime158. The pressure-effect offset calculator determines a pressure-effectoffset based on the strain measurements at various times duringdrilling. The pressure-effect offset calculator determines apressure-effect offset from each of the strain values 156 and/or thestrain values 157. A hydrostatic pressure offset 164 is determined basedon strain values which correspond to an off-bottom, no fluid flow eventor portion of the stand addition. A total pressure offset 166 isdetermined based on strain values which correspond to an off-bottom,fluid flowing even or portion of the stand addition. The total pressureoffset 166 can also be a hydrostatic-and-hydrodynamic pressureoffset—where hydrostatic pressure and hydrodynamic pressure togetherconstitute substantially all pressure experienced in the wellbore. Thatis, the total pressure, and therefore the total pressure offset,corresponds to the hydrostatic pressure (and hydrostatic pressureoffset) and the hydrodynamic pressure (and the hydrodynamic pressureoffset) when other contributions of pressure (such as atmosphericpressure, explosive pressure, surface pressure or surface tension, etc.)are negligible when compared to the hydrostatic pressure andhydrodynamic pressure. Based on the hydrostatic pressure offset 164 andthe total pressure offset 166, the pressure-effect offset calculator 150determines a value for a hydrodynamic pressure offset 168. Thepressure-effect offset calculator 150 can output one or more of thehydrostatic pressure offset 164, the total pressure offset 166, and thehydrodynamic pressure offset 168 to a controller or operator at thesurface 102 during a drilling run, such as via fiber optic telemetry,pressure (i.e., mud pulse) telemetry, etc. The pressure-effect offsetcalculator 150 can also store in memory or communicate for storage inmemory one or more of the hydrostatic pressure offset 164, the totalpressure offset 166, and the hydrodynamic pressure offset 168 to acontroller or operator at the surface 102 during a drilling run forpost-drilling analysis. Alternatively, the pressure-effect offsetcalculator 150 can operate at the surface 102 based on strainmeasurements communicated during a drilling run, such as via fiber optictelemetry, acoustic (i.e., mud pulse) telemetry, etc. or on strainmeasurements previously stored in memory.

The pressure-effect offset calculator 150 can also identify variousportions of the strain addition (such as the off-bottom regime 158(which can comprise both the no flow and off bottom regime and the offbottom with mud flow regime), the on bottom drilling regime 162, etc.)with a trained machine learning algorithm. The machine learningalgorithm can be trained on one or more of WOB, TOB, and RPMmeasurements or strain measurements to identify stand additions and/orportions of stand additions based on the same measurements or fewermeasurements. For example, the machine learning algorithm can be trainedusing supervised training to identify the no flow and off bottom regimebased on strain measurements, where the no flow and off bottom regime inthe training data is identified using both WOB and TOB measurements.

The error checker 180 can then determine redundancy enhanced strainmeasurements 170, based on one or more of the hydrostatic pressureoffset 164, the total pressure offset 166, and the hydrodynamic pressureoffset 168. The error checker 180 can also optionally operate on one ormore of the hydrostatic pressure offset 164, the total pressure offset166, and the hydrodynamic pressure offset 168 together with wellborepath information 172 and/or hydrodynamic information. The wellbore pathinformation 172 can include a wellbore path trajectory, inclination,drill bit geolocation, etc. or any other information about a planned orexecuted wellbore path. The hydrodynamic information 174 can includeinformation about mud weight and mud flow rate, either actual orpredicted. The error checker 180 can detect a change in wellbore orwellbore operation status or condition based on the values of one ormore of the hydrostatic pressure offset 164, the total pressure offset166, and the hydrodynamic pressure offset 168. The error checker 180 canalso detect a change in accuracy, an error, or a value which fallsoutside a predicted or current trend in one or more of the hydrostaticpressure offset 164, the total pressure offset 166, and the hydrodynamicpressure offset 168. The error checker 180 can identify or tag aserroneous a value of one or more of the hydrostatic pressure offset 164,the total pressure offset 166, and the hydrodynamic pressure offset 168and optionally replace an erroneous value with a previous value of thequantity that was not identified as erroneous or a value that isinterpolated or projected using two or more values of the quantity thatwere not identified as erroneous.

The error checker 180 can operate proximate to the pressure-effectoffset calculator 150, such as at the drill bit 120 or at the surface102. The error checker 180 can also operate at the surface 102 based oncommunications received from the pressure-effect offset calculator 150,either during drilling or based on previously collected data. The errorchecker 180 can communicate to a controller or operator at the surface102 during a drilling run, either from within the wellbore 108 or fromanother location at the surface 102. The error checker 180 can also beintegrated within a controller or other processor at the surface 102.

FIG. 2 depicts a flowchart of example operations for determining ahydrostatic pressure-effect offset based on strain measurements. Theflowchart contains example operations described with reference to apressure-effect offset calculator for consistency with earlier figures.The name chosen for the program code is not to be construed as limitingon the claims. Structure and organization of a program can vary due toplatform, programmer/architect preference, programming language, etc. Inaddition, names of code units (programs, modules, methods, functions,etc.) can vary for the same reason and be arbitrary.

At block 202, the pressure-effect offset calculator detects a standaddition for a drillstring in a wellbore. The pressure-effect offsetcalculator can detect the stand addition based on communication from adrilling operation controller, which may initiate or detect the standaddition and communicate to the pressure-effect offset calculator that astand addition is occurring, will occur, or has occurred. The drillingoperator controller may also flag data, such as WOB, TOB, RPM, with astand addition indicator, for both real time data and historical data.The pressure-effect offset calculator can detect the stand additionbased on WOB measurements and, optionally, TOB and RPM measurements,either in real time or based on historical data. The pressure-effectoffset calculator can determine the stand addition based on statisticalor other analysis of the WOB measurements, such as detecting a localminimum or other feature corresponding to a stand addition or off-bottomevent. The pressure-effect offset calculator can also detect the standaddition based on a value threshold, a first derivative or other rate ofchange value, an average value, a standard deviation value, a bandwidththreshold for a rolling window of values, etc. determined from WOBmeasurements. The pressure-effect offset calculator can detect thebeginning of a stand addition, the beginning and end of a standaddition, or can detect individual portions of the stand additionseparately—such as the no flow off bottom regime and the off bottom withmud flow regime. The pressure-effect offset calculator can also detectstable measurements or a set of stable measurements corresponding to thestand addition or either of the regimes.

The pressure-effect offset calculator can detect the stand additionbased on analysis of WOB measurements in conjunction with TOBmeasurements and/or RPM measurements. The pressure-effect offsetcalculator can determine the stand addition based on statistical orother analysis of the TOB measurements, such as detecting a localminimum where TOB measurements are substantially zero or another featurecorresponding to the stand addition or off-bottom event. As TOBmeasurements are calibrated based on torsional strain detectors, TOBmeasurements may be greater than zero (or even negative) if calibrationscontain inaccuracies. A substantially zero TOB measurement can thereforecorrespond to a local minimum or global minimum value for TOB that isnot zero but can be approximately zero or zero to within a threshold.The pressure-effect offset calculator can detect a range or set of timesfor which TOB measurements indicate a stand addition, and then identifyWOB measurements corresponding to the stand addition based onmeasurement times. The pressure-effect offset calculator can also usethe TOB measurements to validate or invalidate a stand addition detectedin WOB measurements. The pressure-effect offset calculator can alsodetect the stand addition based on a value threshold, a first derivativeor other rate of change value, an average value, a standard deviationvalue, a bandwidth threshold for a rolling window of values, etc.determined from TOB measurements.

The pressure-effect offset calculator can determine the stand additionbased on statistical or other analysis of the RPM measurements, such asdetecting a local minimum where RPM measurements are substantially zeroor detecting another feature corresponding to the stand addition oroff-bottom event. As RPM measurements are calibrated based on rotationalvelocity sensors, RPM measurements may be greater than zero (or evennegative) if calibrations contain inaccuracies. RPM measurements canalso be greater than zero even if the drill bit is not being rotated,such as due to momentum from previous rotation. RPM measurements canalso account for more than one source of rotation (i.e., rotation of adrill bit by a positive displacement motor, rotation of a drillstring atthe surface of a wellbore, etc.), where various sources of rotation canbe shut off at different times and/or incompletely stopped. Asubstantially zero RPM measurement can therefore correspond to a localminimum or global minimum value for RPM that is not zero but can beapproximately zero or zero to within a threshold. The pressure-effectoffset calculator can detect a range or set of times for which RPMmeasurements indicate a stand addition, and then identify WOBmeasurements corresponding to the stand addition based on measurementtimes. The pressure-effect offset calculator can also use the RPMmeasurements to validate or invalidate a stand addition detected in WOBmeasurements, together with or in addition to the TOB measurements. Thepressure-effect offset calculator can also detect the stand additionbased on a value threshold, a first derivative or other rate of changevalue, an average value, a standard deviation value, a bandwidththreshold for a rolling window of values, etc. determined from TOBmeasurements.

At block 204, the pressure-effect offset calculator obtains strainmeasurements from a strain gauge associated with the drillstring. Thepressure-effect offset calculator can obtain strain measurements fromthe strain gauge for all available times or data points, or for onlythose times or data points associated with the stand addition. Thepressure-effect offset calculator can obtain strain measurements in anyappropriate form or unit, such as voltages output by the strain gauge,as WOB measurements or other force measurements, etc. Thepressure-effect offset calculator can obtain WOB measurements from astrain gauge located at the drill bit (to identify a stand addition) andadditional strain measurements from a strain gauge located at anotherpoint on the drillstring. If the pressure-effect offset calculatorobtains strain measurements from a strain gauge that does not measureWOB (or measures WOB at a location away from the drill bit), thepressure-effect offset calculator can synchronize or otherwise correlatethe strain measurements to WOB and/or other measurements used toidentify the stand addition or the stand addition times.

At block 206, the pressure-effect offset calculator identifies a set ofstrain measurements from the strain gauge corresponding to anoff-bottom, no fluid flow portion of the stand addition. Thepressure-effect offset calculator can identify the set of strainmeasurements corresponding to the off-bottom, no fluid flow portion ofthe stand addition at the same time as the stand addition is detected,or can detect the set of strain measurements corresponding to theoff-bottom, no fluid flow portion of the stand addition after a standaddition is identified. The pressure-effect offset calculator canidentify an off-bottom portion of the stand addition based on WOBmeasurements, such as by detecting a local minimum in the WOBmeasurements. The pressure-effect offset calculator can identify a nofluid flow portion of the stand addition based on the RPM measurementsof a drill bit, such as by detecting substantially zero RPM for a drillbit or mud motor pump. The pressure-effect offset calculator canidentify the set of strain measurements corresponding to the off-bottom,no fluid flow portion of the stand addition based on an overlap of theoff-bottom and no fluid flow portions of the stand addition and based onone or more of the WOB, RPM, and TOB measurements.

The pressure-effect offset calculator can also identify the set ofstrain measurements corresponding to the off-bottom, no fluid flowportion of the stand addition for which strain measurements arerelatively stable. Relatively stable can comprise strain measurementsfor which a standard deviation or other variance is smaller than apredetermined threshold. Relatively stable can also comprise the set ofstrain measurements corresponding to the off-bottom, no fluid flowportion of the stand addition for which a rolling average is constant orfor which the rolling mean is constant to within a stability threshold.The pressure-effect offset calculator can identify the set of strainmeasurements corresponding to the off-bottom, no fluid flow portion ofthe stand addition and then remove strain measurements at the beginningand the end of the set for which values may be less stable. Variationsin strain measurements can be caused by the drillstring decompressing(i.e., tension or flexion) after the drillstring is pulled off-bottom,or caused by a drill bit or mud motor starting up or ramping down.

At block 208, the pressure-effect offset calculator optionally filtersdata of the set of strain measurements corresponding to the off-bottom,no fluid flow portion of the stand addition. The pressure-effect offsetcalculator can filter the set of strain measurements to determine anaverage, mean, or mode strain value, or a range of strain values (forexample, a mean strain value and a first standard deviation in thestrain values). The pressure-effect offset calculator can filter valuesnegatively (i.e., remove values of the set) or positively (i.e., selectvalues for the set). The pressure-effect offset calculator can determineif one or more values of the set of strain measurements corresponding tothe off-bottom, no fluid flow portion of the stand addition correspondsto noise or another non-pressure related effect—such as an unexpectedweight transfer event like a collision with a side of the wellbore ortouching down on the bottom of the wellbore. The pressure-effect offsetcalculator can alternatively select a portion of the set of strainmeasurements corresponding to a stable or the most stable portion of theoff-bottom, no fluid flow portion of the stand addition.

At block 210, the pressure-effect offset calculator determines ahydrostatic pressure-effect offset value from the set of strainmeasurements corresponding to the off-bottom, no fluid flow portion ofthe stand addition based on a zero point for the strain measurements.Strain measurements are usually made in millivolt (mV) per volt (V) ormV/V. The pressure-effect offset calculator can calculate thehydrostatic pressure-effect offset value in the same units as the strainmeasurements, in equivalent units, or in another unit which can beconverted to the units of the strain measurement. Optionally, thepressure-effect offset calculator can convert the strain measurements toanother metric (such as pressure measurements in pounds per square inch(psi) or any other appropriate unit, or force measurements in pounds(lbs). The pressure-effect offset calculator can also determine thehydrostatic pressure-effect offset in units of pressure, force, etc.either based on strain measurements or can determine the hydrostaticpressure-effect offset in units of strain measurement and then convertthe hydrostatic pressure-effect offset to any other appropriate unit ofmeasure (such as units of strain, which may be dimensionless, units ofpressure, units of force, units of energy, etc.).

The pressure-effect offset calculator determines the hydrostaticpressure-effect offset based on a zero point for the strainmeasurements. The pressure-effect offset calculator can determine thatthe entirety of the strain measurement value during the off-bottom, nofluid flow portion of the strain measurements corresponds to thehydrostatic pressure-effect offset. The pressure-effect offsetcalculator can also determine that a portion of the strain measurementvalue during the off-bottom, no fluid flow portion of the strainmeasurement corresponds to a zero value for the strain measurement. Forexample, a strain gauge measures a value of 0 mV/V at a pressure of zeroor at the surface of a wellbore before the strain gauge is introducedinto the wellbore. The strain gauge then measures a value of 1 mV/Vduring the hydrostatic portion of a stand addition. Accordingly, thepressure-effect offset calculator determines that the hydrostaticpressure-effect offset is 1 mV/V or the difference between the zeropoint (i.e., 0 mV/V and the strain measurements of 1 mV/V during theoff-bottom, no fluid flow portion of the stand addition). However, thestrain gauge may not measure a value of 0 mV/V at the zero point, as azero point may be chosen arbitrarily, and strain gauge values can befurther affected by temperature of the filament or other elements of thestrain gauge when the measurement is taken. In a second example, astrain gauge measures a value of 0.1 mV/V at a pressure of zero or atthe surface of a wellbore before the strain gauge is introduced into thewellbore. The strain gauge then measures a value of 1.2 mV/V during thehydrostatic portion of a stand addition. In this second example case,the pressure-effect offset calculator determines that a zero-pointoffset is |0.1| mV/V and the hydrostatic pressure-effect offset is 1.1mV/V or 1.2 mV/V. That is, the pressure-effect offset calculator caninclude or exclude an additional zero-point offset. In some cases, suchas where temperature varies widely along the wellbore, thepressure-effect offset calculator can preferentially include multipleoffsets caused by other-than-pressure effects (i.e.,pre-tensioning-effect offset, expansion-effect offset, etc.) within thehydrostatic pressure-effect offset because other offsets are lessrelevant or much smaller than the pressure-effect offset.

The pressure-effect offset calculator can determine a single value ofthe hydrostatic pressure-effect offset, can determine a range of values,can determine a mean and standard deviation for a set of values, etc.The pressure-effect offset calculator can optionally filter the valuesof the hydrostatic pressure-effect offset after determination, insteadof filtering the data of the set of strain measurements. Thepressure-effect offset calculator can determine multiple values, butstore or transmit fewer than all values based on, for example,transmission or storage limitations.

At block 212, the pressure-effect offset calculator outputs thehydrostatic pressure-effect offset value for monitoring of a wellboreoperation. The pressure-effect offset calculator can output thehydrostatic pressure-effect offset value to a surface drilling operatoror controller. Optionally, the pressure-effect offset calculator cantrigger an alert if the hydrostatic pressure-effect value if thehydrostatic pressure-effect value falls outside a predetermined range ordisplays a change from a previous value greater than a predeterminedthreshold—i.e., the pressure-effect offset calculator can trigger analert for a set of predetermined hydrostatic pressure-effect offsetvalues. The pressure-effect offset calculator can output the hydrostaticpressure-effect offset to storage or memory for retrieval after thecompletion of the drilling run. The pressure-effect offset calculatorcan also compare a current hydrostatic pressure-effect offset to ahydrostatic pressure-effect offset calculated for a previous standaddition and store the hydrostatic pressure-effect offset forcalculation of a hydrodynamic pressure-effect offset in the standaddition.

FIG. 3 depicts a flowchart of example operations for determining ahydrodynamic pressure-effect offset based on strain measurements. Theflowchart contains example operations described with reference to apressure-effect offset calculator for consistency with earlier figures.The operations for blocks 302, 304, 306, 308, and 310 are similar tooperations for blocks 202, 204, 206, 208, and 210, respectively.

At block 302, the pressure-effect offset calculator detects a standaddition for a drillstring in a wellbore.

At block 304, the pressure-effect offset calculator obtains strainmeasurements from a strain gauge associated with the drillstring.

At block 306, the pressure-effect offset calculator identifies a set ofstrain measurements from the strain gauge corresponding to anoff-bottom, no fluid flow portion of the stand addition.

At block 308, the pressure-effect offset calculator optionally filtersdata of the set of strain measurements corresponding to the off-bottom,no fluid flow portion of the stand addition.

At block 310, the pressure-effect offset calculator determines ahydrostatic pressure-effect offset value from the set of strainmeasurements correspond to the off-bottom, no fluid flow portion of thestand addition based on a zero point for the strain measurements.

At block 314, the pressure-effect offset calculator identifies a set ofstrain measurements from the strain gauge corresponding to anoff-bottom, fluid flowing portion of the stand addition. Thepressure-effect offset calculator can identify the set of strainmeasurements corresponding to the off-bottom, fluid flowing portion ofthe stand addition at the same time as the stand addition is detected,or can detect the set of strain measurements corresponding to theoff-bottom, fluid flowing portion of the stand addition after a standaddition is identified. The pressure-effect offset calculator canidentify the off-bottom, fluid flowing portion of the stand additionwhile also identifying the off-bottom, no fluid flowing portion of thestand addition, such as in block 306. The pressure-effect offsetcalculator can identify an off-bottom portion of the stand additionbased on WOB measurements, such as by detecting a local minimum in theWOB measurements. The pressure-effect offset calculator can identify thefluid flowing portion of the stand addition based on the RPMmeasurements of a drill bit, such as by detecting a non-zero RPM for adrill bit or mud motor pump. The pressure-effect offset calculator canalso identify the fluid flowing portion of the stand addition or thestart of the fluid flowing portion of the stand addition based on anabrupt increase (or a gradual and substantial increase) in RPM and/orTOB corresponding to a ramp up of a drill bit or mud motor pump. Thepressure-effect offset calculator can identify the set of strainmeasurements corresponding to the off-bottom, fluid flowing portion ofthe stand addition based on an overlap of the off-bottom and fluidflowing portions of the stand addition and based on one or more of theWOB, RPM, and TOB measurements.

The pressure-effect offset calculator can also identify the set ofstrain measurements corresponding to the off-bottom, fluid flowingportion of the stand addition for which strain measurements arerelatively stable. Relatively stable strain measurements can be strainmeasurements for which a standard deviation or other variance is smallerthan a predetermined threshold. Relatively stable strain measurementscan be the set of strain measurements corresponding to the off-bottom,fluid flowing portion of the stand addition for which a rolling averageis constant or for which the rolling mean is constant to within astability threshold. The pressure-effect offset calculator can identifythe set of strain measurements corresponding to the off-bottom, fluidflowing portion of the stand addition and then remove strainmeasurements at the beginning and the end of the set for which valuesmay be less stable.

At block 316, the pressure-effect offset calculator optionally filtersdata of the set of strain measurements corresponding to the off-bottom,fluid flowing portion of the stand addition. The pressure-effect offsetcalculator can filter the set of strain measurements to determine anaverage, mean, or mode strain value, or a range of strain values (forexample, a mean strain value and a first standard deviation in thestrain values). The pressure-effect offset calculator can filter valuesnegatively or positively. The pressure-effect offset calculator candetermine if one or more values of the set of strain measurementscorresponding to the off-bottom, fluid flowing portion of the standaddition corresponds to noise or another non-pressure related effect.The pressure-effect offset calculator can alternatively select a portionof the set of strain measurements corresponding to a stable or moststable portion of the off-bottom, fluid flowing portion of the standaddition. As an example, the pressure-effect offset calculator canselect a subset of the set of strain measurements corresponding to theoff-bottom, fluid flowing portion of the stand addition for which arolling average increases less than a threshold.

At block 318, the pressure-effect offset calculator determines a totalpressure-effect offset value from the set of strain measurementscorresponding to the off-bottom, fluid flowing portion of the standaddition based on a zero point for the strain measurements. The totalpressure-effect offset is a pressure-effect offset for the hydrodynamicregime, which is the off-bottom, fluid flowing portion of the standaddition and includes contributions due to both hydrostatic pressure(which generates the hydrostatic pressure-effect offset) andhydrodynamic pressure (which generates the hydrodynamic pressure-effectoffset). The total pressure-effect offset can be any pressure-effectoffset associated with the hydrodynamic regime. The pressure-effectoffset calculator determines a total pressure-effect offset based on azero point for the strain measurements, which may be the same zero pointused to determine the hydrostatic pressure-effect offset in block 310(and as previously described with reference to block 210). The zeropoint for the strain measurements may also be the hydrostaticpressure-effect offset, such as that calculated in block 310 or anotherappropriate zero-point offset. In some cases, the zero point for thestrain measurements can depend on temperature and the hydrostaticpressure-effect offset and the total pressure-effect offset can bedetermined based on different zero points for the strain measurements iftemperature changes between measurements.

At block 320, the pressure-effect offset calculator determines ahydrodynamic pressure-effect offset based on a difference between thehydrostatic pressure-effect offset and the total pressure-effect offset.The hydrodynamic pressure-effect offset is a measure of a change inzero-point offset between the hydrostatic regime, which is theoff-bottom, no fluid flow portion of the stand addition, and thehydrodynamic regime, which is the off-bottom, fluid flowing portion ofthe stand addition. The pressure-effect offset calculator can determinethe hydrodynamic pressure-effect offset in any appropriate manner, suchas those described in blocks 310 and 320.

The pressure-effect offset calculator determines the hydrodynamicpressure-effect offset based on a difference between the hydrostaticpressure and the total pressure-effect offset, which can be determinedin any comparable units such as voltage (e.g., mV/V), current, lbs, psi,etc.

At block 322, the pressure-effect offset calculator outputs thehydrodynamic pressure-effect offset for monitoring of a wellboreoperation. The pressure-effect offset calculator can output thehydrodynamic pressure-effect offset to a surface drilling operator orcontroller. Optionally, the pressure-effect offset calculator cantrigger an alert if the hydrodynamic pressure-effect offset fallsoutside a predetermined range or displays a change from a previous valueor from a hydrostatic pressure-effect offset greater than apredetermined threshold—i.e., the pressure-effect offset calculator cantrigger an alert for a set of predetermined hydrodynamic pressure-effectoffset values. The pressure-effect offset calculator can output thehydrodynamic pressure-effect offset to storage or memory for retrievalafter the completion of the drilling run. The pressure-effect offsetcalculator can also compare a current hydrodynamic pressure-effectoffset to a hydrodynamic pressure-effect offset calculated for aprevious stand addition. The pressure-effect offset calculator can alsooutput the hydrostatic pressure-effect offset and/or the measure oftotal pressure-effect offset with the hydrodynamic pressure-effectoffset.

Although calculation of both a total pressure-effect offset and ahydrodynamic pressure-effect offset are depicted in FIG. 3 , embodimentsdo not necessarily calculate both. A total pressure-effect offset may beused in in place of a hydrodynamic pressure-effect offset. In somecases, only a hydrodynamic pressure-effect offset is used. Thepressure-effect offset calculator can determine the hydrodynamicpressure-effect offset directly from the set of strain measurementscorresponding to the off-bottom, fluid flowing portion of the strainmeasurements without first or explicitly determining the totalpressure-effect offset and/or the hydrostatic pressure-effect offset.Hereinafter, instances of hydrodynamic pressure-effect offset should beunderstood to include operations conducted instead or additionally withthe total pressure-effect offset.

FIG. 4 depicts a flowchart of example operations for checking for errorin the hydrostatic pressure-effect offset. The flowchart containsexample operations described with reference to an error checker forconsistency with earlier figures. The name chosen for the program codeis not to be construed as limiting on the claims. Structure andorganization of a program can vary due to platform, programmer/architectpreference, programming language, etc. In addition, names of code units(programs, modules, methods, functions, etc.) can vary for the samereason and be arbitrary.

At block 402, the error checker detects a stand addition for adrillstring in a wellbore. The error checker can detect a stand additionas previously described with respect to block 202. The error checker canalternatively detect a stand based on a trigger or data tag from thepressure-effect offset calculator.

At block 410, the error checker determines a hydrostatic pressure-effectoffset value for the detected stand. As previously described withreference to FIGS. 2 and 3 , a pressure-effect offset calculator candetermine the hydrostatic pressure-effect offset value. Thefunctionality of the pressure-effect offset calculator can beimplemented as part of the error checker or can be separate from theerror checker.

At block 424, the error checker determines a change in the hydrostaticpressure-effect offset value based on a difference between thehydrostatic pressure-effect offset value for the detected stand and atleast a previously determined hydrostatic pressure-effect offset value.The error checker can access a previously determined hydrostaticpressure-effect offset from a previous stand. The error checker canstore a previously determined hydrostatic pressure-effect offsetcalculated for the wellbore, such as a predicted pressure-effect offsetbased on a wellbore model. The error checker can determine a change inthe hydrostatic pressure-effect offset value based on multiplepreviously determined hydrostatic pressure-effect offset values. Forexample, the error checker can determine if the hydrostaticpressure-effect offset value falls within a standard deviation of a meanof a set of previously determined hydrostatic pressure-effect offsetvalues. In another example, the error checker can determine the changein hydrostatic pressure-effect offset is greater or smaller than athreshold.

At block 426, the error checker optionally determines an expected changein the hydrostatic pressure-effect offset based on a wellboretrajectory. Wellbore trajectory can include at least one of a planned ormeasured depth, diameter, inclination, orientation, or other trajectorydata. The wellbore trajectory can be determined based on one or moresensor measurement or data from one or more tool, including loggingwhile drilling (LWD) and measurement while drilling (MWD) tools. Thewellbore trajectory can also include a planned, projected, or predictedwellbore trajectory measurement and a measurement of deviation from theplanned wellbore trajectory. The error checker can determine theexpected change based on the wellbore trajectory for a drilling run orportion of a drilling run. That is, the error checker can determine theexpected change based on the cumulative wellbore trajectory. The errorchecker can determine the expected change based on a difference in thewellbore trajectory for the detected stand addition and a locationassociated with the previously determined hydrostatic pressure-effectoffset value. That is, the error checker can determine the expectedchange iteratively or incrementally.

The error checker can determine the expected change based on geometriccalculations of hydrostatic pressure, for example using the relationshipof Eq. 1. The error checker can determine the expected change basedadditionally on the direction of gravity at the strain gauge, wherehydrostatic pressure is a function of normal forces which change fornon-vertical wells. In some examples, the expected change in hydrostaticpressure can be negative, such as for wellbores which trend upwards(i.e., against gravity) in lateral legs. The error checker can determinethe expected change based on one or more wellbore model. The errorchecker can determine the expected change as a measure of pressure(e.g., in lbs per unit area), as a measure of strain (e.g., in mV/V), orin any other appropriate unit. For example, the error checker cancalculate the expected change in the hydrostatic pressure as a pressureand then convert the expected change in the hydrostatic pressure to anexpected change in the hydrostatic pressure-effect offset based on arelationship between strain measurements or strain responses for astrain gauge and pressure.

At block 428, the error checker optionally determines an expected changein the hydrostatic pressure-effect offset based on a change in mudweight. Mud weight can encompass various fluid pressure, such as mass,density, etc. The error checker can determine an expected change basedon changes in additional mud properties, such as viscosity, diffusivity,etc. The error checker can determine if the mud weight (or another fluidproperty) has changed and if the mud weight has not changed, determinethat the expected change is zero or negligible. If error checkerdetermines that the mud weight has changed, the error checker can thenoutput an expected change in the hydrostatic pressure-effect based onthe determined mud weight change. A change in mud weight can be detectedby another program or controller, such as identified by a mud pump oroperator at the surface, and transmitted to the error checker. The errorchecker can determine if the mud weight has changed based on an averagemud weight or other composite value for the wellbore or wellboreoperation. The error checker can determine that the mud weight haschanged based on an influx of formation fluid into the wellbore or basedon an outflow of drilling mud to the formation. The error checker candetermine that the mud weight has changed based on presence or absenceof drilling cuttings, gas entrapment, etc.

A change in mud weight can be determined based on one or more sensormeasurement or data from one or more tool, including logging whiledrilling (LWD) and measurement while drilling (MWD) tools. The errorchecker can determine the expected change based on the mud weight for adrilling run or portion of a drilling run. That is, the error checkercan determine the expected change based on the cumulative mud weight.The error checker can determine the expected change based on adifference in the mud weight for the detected stand and a locationassociated with the previously determined hydrostatic pressure-effectoffset value. That is, the error checker can determine the expectedchange iteratively or incrementally. The expected change in hydrostaticpressure can be positive or negative based on the direction of thechange in mud weight. The error checker can determine the expectedchange based on one or more wellbore and/or mud weight model. The errorchecker can determine the expected change as a measure of pressure(e.g., in lbs per unit area), as a measure of strain (e.g., in mV/V), orin any other appropriate unit. For example, the error checker cancalculate the expected change as a pressure and then convert theexpected change in the hydrostatic pressure to an expected change in thehydrostatic pressure-effect offset based on a relationship betweenstrain measurements or strain responses for a strain gauge and pressure.

At block 440, the error checker determines if the change in thehydrostatic pressure-effect offset value conforms to expected trend(s).The error checker can determine whether or not the determined change inthe hydrostatic pressure-effect offset value conforms to one or moreexpected trend, where the expected trends can include at least one of:(1) substantial stability between subsequent stands, (2) increase inpressure-effect offset due to depth, and/or (3) proportionality with mudweight changes. The error checker can determine if the change in thehydrostatic pressure-effect offset is generally stable between standsand during stand additions. For example, if the off-bottom, no fluidflow portion of the stand addition takes five (5) minutes, the errorchecker can determine if the hydrostatic pressure-effect offset valuedrifts or changes during that time. In another example, the errorchecker can determine if the value of the hydrostatic pressure-effectoffset changes by less than a threshold between subsequent or sequentialstand additions. The threshold can instead be a range of values. Theerror checker can also determine if the change in the hydrostaticpressure-effect offset is generally stable over a drilling run, such asfor each stand addition or a portion of the stand additions of adrilling run. Stable in this case can mean stable to within a margin oferror or threshold. The error checker can also determine that the changein the pressure-effect offset generally conforms to a trend, such asincreasing linearly, increasing sub-linearly, increasing exponentially,etc. The error checker can then determine if the change in thehydrostatic pressure-effect offset value for the detected stand additionconforms to the pattern of other hydrostatic pressure-effect offsetvalues. The error checker can identify or fit a pattern in thehydrostatic pressure-effect offset values or the change in thehydrostatic pressure-effect offset values. The error checker candetermine if the hydrostatic pressure-effect offset conforms to theexpected trend(s) based on machine learning.

The error checker can also determine if the change in the hydrostaticpressure-effect offset conforms to the expected change determined basedon the wellbore trajectory (in block 426) and/or the expected changedetermined based on the change in mud weight (in block 428). If theerror checker determines that the change in the hydrostaticpressure-effect offset conforms to expected trend(s), flow continues toblock 444. If the error checker determines that the change in thehydrostatic pressure-effect offset does not conform to expectedtrend(s), flow continues optionally to block 442 or to block 446.

At block 442, the error checker optionally determines if the change inthe hydrostatic pressure-effect offset value indicates unexpectedwellbore conditions. The error checker can attempt to determine if thehydrostatic pressure-effect offset value is a result of an error in thestrain measurements or an unexpected event in the wellbore. Anunexpected change in hydrostatic pressure can be caused by an unexpectedchange in mud weight, an unexpected wellbore trajectory (such asunexpected depth, inclination, etc.), an unexpected influx or outflowinto the wellbore, etc. An unexpected change in the hydrostaticpressure-effect offset can therefore be a result of a real butunexpected wellbore condition or event and can be used to detect theseconditions and events. The error checker can trigger a warning to theoperator or a controller of the wellbore operation that an unexpectedhydrostatic pressure-effect offset is determined.

The error checker can also determine if the change in the hydrostaticpressure-effect offset indicates unexpected wellbore conditions based onmultiple hydrostatic pressure-effect offset values and/or values formultiple stand additions. For example, the error checker can determinethat a single hydrostatic pressure-effect offset value which does notconform to an expected trend is erroneous but then determine, based onmultiple hydrostatic pressure-effect offset values which do not conformor even indicated a new or different trend is occurring, determine thatthe change indicates an unexpected wellbore condition. The error checkercan determine if the change indicated unexpected wellbore conditionsbased on a threshold number of hydrostatic pressure-effect offset valuesor a threshold change in the hydrostatic pressure-effect offset value.For example, the error checker can determine that the hydrostaticpressure-effect offset value is increasing at a first value per standaddition for a first portion of the wellbore and then determine that thehydrostatic pressure-effect offset value is increasing at a second valueper stand addition for a second portion of the wellbore. The errorchecker can implement various control methods, such as standarddeviation monitoring (i.e., six sigma) and the like, to detect andpredict changes in the hydrostatic pressure-effect offset and trends inchanges in the hydrostatic pressure-effect offset. If the error checkerdetermines that the change in the hydrostatic pressure-effect offsetindicates unexpected wellbore conditions, flow continues to block 444.If the error checker determines that the change in the hydrostaticpressure-effect offset does not indicate unexpected wellbore conditions,flow continues to block 446.

At block 444, the error checker outputs the hydrostatic pressure-effectoffset value for the current stand for strain measurement determination.The error checker can output the hydrostatic pressure-effect offsetvalue to a strain measurement zeroing system or controller, to apressure calculator, to a WOB calculator, etc. The error checker canoutput the hydrostatic pressure-effect offset value to storage or memoryor append the hydrostatic pressure-effect offset to strain measurementdata sets, where it can be accessed by any program accessing the strainmeasurements. The error checker can also subtract the hydrostaticpressure-effect offset from the strain measurements and output a set ofstrain measurements which have been zeroed or tared to account for thehydrostatic pressure-effect offset.

At block 446, the error checker determines that the hydrostaticpressure-effect offset for the current stand is erroneous and outputsthe previously determined hydrostatic pressure-effect offset value forstrain measurement determination. The error checker can discard theerroneous hydrostatic pressure-effect offset, or can report or store theerroneous hydrostatic pressure-effect offset such as for error analysisand analysis of trends in the hydrostatic pressure-effect offset. Forexample, the error checker can determine that a first hydrostaticpressure-effect offset value is erroneous, but then based on at least asecond hydrostatic pressure-effect offset value determine that the firstvalue was not erroneous but instead indicated an unexpected wellborecondition and can recalculate or cause to be recalculated various strainmeasurements using the first value which was previously marked aserroneous.

The error checker can output the previously determined hydrostaticpressure-effect offset value to a strain measurement zeroing system orcontroller, to a pressure calculator, to a WOB calculator, etc. Theerror checker can output the previously hydrostatic pressure-effectoffset value to storage or memory or append the previously determinedhydrostatic pressure-effect offset to strain measurement data sets,where it can be accessed by any program accessing the strainmeasurements. The error checker can also subtract the previouslydetermined hydrostatic pressure-effect offset from the strainmeasurements and output a set of strain measurements which have beenzeroed or tared to account for the hydrostatic pressure-effect offset.

At block 448, the error checker determines if an additional stand isdetected. The error checker can also detect an additional stand based onan additional trigger from the pressure-effect offset calculator orbased on receipt of an additional strain measurements. If an additionalstand is detected, flow continues to block 410 where the error checkerdetermines a hydrostatic pressure-effect offset for the detected stand.

FIG. 5 depicts a flowchart of example operations for checking for errorin the hydrodynamic pressure-effect offset. The flowchart containsexample operations described with reference to an error checker forconsistency with earlier figures. The operations for blocks 502, 510,540, 542, 544, 546, and 548 are similar to operations for block 402,410, 440, 442, 444, 446, and 448, respectively.

At block 502, the error checker detects a stand addition for adrillstring in a wellbore.

At block 510, the error checker determines a hydrodynamicpressure-effect offset value for the detected stand. As previouslydescribed with reference to FIG. 3 , a pressure-effect offset calculatorcan determine the hydrodynamic pressure-effect offset value. Thefunctionality of the pressure-effect offset calculator can beimplemented as part of the error checker or can be separate from theerror checker.

At block 524, the error checker determines a change in the hydrodynamicpressure-effect offset value based on a difference between thehydrostatic pressure-effect offset value for the detected stand and atleast a previously determined hydrostatic pressure-effect offset value.The error checker can determine the change in the hydrodynamicpressure-effect offset using any method appropriate for determining thehydrostatic pressure-effect offset, such as those described in referenceto block 410.

At block 530, the error checker optionally determines an expected changein the hydrodynamic pressure-effect offset based on a change in mudweight and/or flow rate. Hydrodynamic pressure is a function of both mudweight and flow rate, but not of depth. The error checker can determinethe expected change in the hydrodynamic pressure-effect based on thechange in mud weight using any method appropriate for determining theexpected change in the hydrostatic pressure-effect offset due to achange in mud weight, such as those described in reference to block 428.

The error checker can determine if the flow rate has changed and if theflow rate has not changed, determine that the expected change is zero ornegligible. If error checker determines that the flow rate has changed,the error checker can then output an expected change in the hydrodynamicpressure-effect based on the determined change. A change in flow ratecan be detected by another program or controller, such as identified bya flow monitor or operator at the surface, and transmitted to the errorchecker. The error checker can determine if the flow rate has changedbased on an average flow rate or other composite value for the wellboreor wellbore operation.

Changes in mud weight and flow rate can be additive or subtractive, asthe hydrodynamic pressure depends on a number of fluid factors (e.g.,density, viscosity, diffusivity, etc.) and fluid flow rates. Changes inmud weight and flow rate can be offsetting—i.e., the expected change inthe hydrodynamic pressure-effect offset for an example change in mudweight and a concurrent example change in flow rate can be zero (ornegligible), positive, or negative. The error checker can determine theexpected change based on the change in mud weight and/or the change inflow rate for a drilling run or portion of a drilling run. That is, theerror checker can determine the expected change based on the cumulativemud weight and/or flow rate. The error checker can determine theexpected change based on a difference in the mud weight and/or flow ratefor the detected stand and a location associated with the previouslydetermined hydrostatic pressure-effect offset value. That is, the errorchecker can determine the expected change iteratively or incrementally.The expected change in hydrodynamic pressure can be positive or negativebased on the direction of the change in mud weight and/or flow rate. Theerror checker can determine the expected change based on one or morewellbore, mud weight, and flow rate model. The error checker candetermine the expected change as a measure of pressure (e.g., in lbs perunit area), as a measure of strain (e.g., in mV/V), or in any otherappropriate unit. For example, the error checker can calculate theexpected change as a pressure and then convert the expected change inthe hydrodynamic pressure to an expected change in the hydrodynamicpressure-effect offset based on a relationship between strainmeasurements or strain responses for a strain gauge and pressure.

At block 540, the error checker determines if the change in thehydrodynamic pressure-effect offset value conforms to expected trend(s).The error checker can determine whether or not the determined change inthe hydrodynamic pressure-effect offset value conforms to one or moreexpected trend, where the expected trends can include at least one of:(1) substantial stability between subsequent stands, (2) increase inpressure-effect offset due to increase in flow rate, and/or (3) increasein pressure-effect offset due to increase in mud weight. The errorchecker can determine if the change in the hydrodynamic pressure-effectoffset is generally stable between stands and during stand additions.Hydrodynamic pressure, when controlling for mud weight and flow rate, isindependent of depth and should remain stable between stands and standadditions. For example, if the off-bottom, fluid flowing portion of thestand addition takes two (2) minutes, the error checker can determine ifthe hydrodynamic pressure-effect offset value drifts or changes duringthat time. In another example, the error checker can determine if thevalue of the hydrodynamic pressure-effect offset changes by less than athreshold between subsequent or sequential stand additions. Thethreshold can instead be a range of values. The error checker can alsodetermine if the change in the hydrodynamic pressure-effect offset isgenerally stable over a drilling run, such as for each stand addition ora portion of the stand additions of a drilling run. Stable in this casecan mean stable to within a margin of error or threshold. The errorchecker can determine if the hydrostatic pressure-effect offset conformsto the expected trend(s) based on machine learning.

The error checker can also determine if the change in the hydrodynamicpressure-effect offset conforms to expected change determined based onthe change in mud weight and/or flow rate (in block 530). If the errorchecker determines that the change in the hydrodynamic pressure-effectoffset conforms to expected trend(s), flow continues to block 544. Ifthe error checker determines that the change in the hydrodynamicpressure-effect offset does not conform to expected trend(s), flowcontinues optionally to block 544 or to block 546.

At block 542, the error checker optionally determines if the change inthe hydrodynamic pressure-effect offset value indicates unexpectedwellbore conditions. The error checker can determine if the change inthe hydrodynamic pressure-effect offset value indicates unexpectedwellbore conditions using any method appropriate for determining if thechange in the hydrostatic pressure-effect offset value indicatedunexpected wellbore conditions, such as those described in reference toblock 442. If the error checker determines that the change in thehydrodynamic pressure-effect offset indicates unexpected wellboreconditions, flow continues to block 544. If the error checker determinesthat the change in the hydrodynamic pressure-effect offset does notindicate unexpected wellbore conditions, flow continues to block 546.

At block 544, the error checker outputs the hydrodynamic pressure-effectoffset value for the current stand for strain measurement determination.The error checker can output the hydrodynamic pressure-effect offsetvalue using any method appropriate for outputting the hydrostaticpressure-effect offset value, such as those described in reference toblock 444.

At block 546, the error checker determines that the hydrodynamicpressure-effect offset for the current stand is erroneous and outputsthe previously determined hydrodynamic pressure-effect offset value forstrain measurement determination. The error checker can determine thatthe hydrodynamic pressure-effect offset is erroneous and output thepreviously determined hydrodynamic pressure-effect offset value usingany method appropriate for determining the hydrostatic pressure-effectoffset is erroneous and outputting the previously determined hydrostaticpressure-effect offset, such as those described in reference to block446.

At block 548, the error checker determines if an additional stand isdetected. If an additional stand is detected, flow continues to block510 where the error checker determines a hydrostatic pressure-effectoffset for the detected stand.

The flowcharts are provided to aid in understanding the illustrationsand are not to be used to limit scope of the claims. The flowchartsdepict example operations that can vary within the scope of the claims.Additional operations may be performed; fewer operations may beperformed; the operations may be performed in parallel; and theoperations may be performed in a different order. For example, theoperations depicted in blocks 426 and 428 can be performed in parallelor concurrently. With respect to FIG. 2 , data filtration is notnecessary. It will be understood that each block of the flowchartillustrations and/or block diagrams, and combinations of blocks in theflowchart illustrations and/or block diagrams, can be implemented byprogram code. The program code may be provided to a processor of ageneral-purpose computer, special purpose computer, or otherprogrammable machine or apparatus.

FIGS. 6A, 6B, and 6C depict graphs corresponding to tared strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit during addition of a stand. FIG. 6A depicts agraph 600 displaying weight on bit (WOB) in pounds after hydrostaticpressure is removed along y-axis 602 as a function of time along x-axis604. The graph 600 depicts WOB values that have been zeroed or tared toremove hydrostatic pressure during the stand addition, in order toimprove calculation of WOB during drilling (i.e., during the portions ofdrilling where the drill bit is drilling, outside of stand additions).Taring and zeroing includes any setting or resetting of a measurement toa zero-value based on a reference point. A line 606 is formed by dotsrepresenting tared values of WOB determined from a strain gauge for adrillstring in a wellbore during various portions of a stand addition.

During the time period covered by an arrow 610, the drillstring is inthe off-bottom, no fluid flow portion of the stand addition. The arrow610 identifies values of WOB that are substantially zero, where the WOBvalues have been tared to remove hydrostatic pressure from the WOBmeasurements. During the time period covered by an arrow 612, thedrillstring is in the off-bottom, fluid flowing portion of the standaddition. The arrow 612 identifies values of WOB that are relativelysteady, except for a peak 614. The graph 600 displays WOB values whichhave been tared to remove the hydrostatic pressure (e.g., WOBmeasurements corresponding to the arrow 610) and therefore displaysincreases in pressure from the hydrostatic pressure during subsequenttime periods (i.e., time periods after those identified by the arrow610). The peak 614 represents an increase in WOB measurements due to acontribution from hydrodynamic pressure. The decrease in the peak 614 isa function of stabilization of WOB which occurs after a surge due to theinitial fluid flow as the pumps turn on. The arrow 612 identifies valuesthat have been incompletely zeroed to remove hydrodynamic pressure fromthe WOB measurements, where the values are not substantially zero due toincomplete taring of values. The WOB values are instead represented byan arrow 616, which corresponds to the WOB contribution fromhydrodynamic pressure after the contribution from hydrostatic pressureis removed.

A dashed line 617 represents the time at which fluid flow begins, andwhich separates the hydrostatic regime of the arrow 610 form thehydrostatic-and-hydrodynamic regime of the arrow 612. A dashed line 618represents the time at which the drill bit is brought back into contactwith the bottom of the wellbore (e.g., pick up of WOB). The line 606increases as WOB is added back onto the drillstring, until at a timeperiod identified by an arrow 620 the WOB on the drillstring reaches asteady state.

FIG. 6B depicts a graph 630 displaying torque on bit (TOB) along y-axis632 as a function of time along x-axis 634. The graph 630 depicts TOBvalues during the stand addition, which can be used to identify regionsand/or portions of the stand addition. A line 636 is formed by dotsrepresenting TOB determined from a torsional strain gauge (or anothersensor) for a drillstring in a wellbore during various portions of astand addition.

During the time period covered by an arrow 640, the drillstring is inthe off-bottom, no fluid flow portion of the stand addition. The arrow640 identifies values of TOB that correspond to a local minimum, wherefluid is not flowing and the drill bit and/or mud motor are not rotatingand not creating torque on the bit. During the time period covered by anarrow 642, the drillstring is in the off-bottom, fluid flowing portionof the stand addition. The arrow 642 identifies values of TOB that arerelatively steady, except for a peak indicated by an arrow 644. The peakat the arrow 644 represents an increase in TOB measurements due to atouchdown of the drill bit as it is brough back into contact with thewellbore bottom. The arrow 646 represents an increase in TOB between theoff-bottom, no fluid flow and off-bottom, fluid flowing portions of thestand addition.

A dashed line 647 represents the time at which fluid flow begins, andwhich separates the hydrostatic regime of the arrow 640 form thehydrostatic-and-hydrodynamic regime of the arrow 642. A dashed line 648represents the time at which the drill bit is brought back into contactwith the bottom of the wellbore, or pick up of WOB. After thedrillstring comes back into contact with the bottom (during the timeperiod covered by an arrow 650), the TOB increases to a value indicatedby the arrow 644 and then increases substantially to return to a steadystate value for drilling (e.g., the steady state value indicated by anarrow 650). It should be understood that the values indicated by thearrow 644 and the arrow 650 are different enough (such that the valueindicated by the arrow 650 is much larger than the value indicated bythe arrow 644 and can be orders of magnitude larger) that they areseparated by a break 633 in the y-axis corresponding to TOB in order toallows such values to be plotted on a single graph while preserving theinformation contained in the TOB for off-bottom portions of the standaddition.

FIG. 6C depicts a graph 660 displaying drill bit rotation per minute(RPM) along y-axis 662 as a function of time along x-axis 664. The graph660 depicts RPM values during the stand addition, which can be used toidentify regions and/or portions of the stand addition. A line 666 isformed by dots representing RPM determined from a rotational velocitysensor (or another sensor) for a drillstring in a wellbore duringvarious portions of a stand addition.

During the time period covered by an arrow 670, the drillstring is inthe off-bottom, no fluid flow portion of the stand addition. The arrow670 identifies values of RPM that are substantially zero. During thetime period covered by an arrow 672, the drillstring is in theoff-bottom, fluid flowing portion of the stand addition. The arrow 672identifies values of RPM that are relatively steady about an RPM valuerepresented by an arrow 676, except for peaks 673 and 674. The peak 673represents an increase in RPM due to ramp up of a drill bit or mud motoras fluid begins to flow through the drillstring. The peak 674 representsan increase in RPM measurements due to touchdown of the drill bit as itis brought back into contact with the wellbore bottom. The peak 674 canalso represent a measurement artifact and may not correspond to anactual RPM increase.

A dashed line 682 represents the time at which fluid flow begins, andwhich separates the hydrostatic regime of the arrow 670 form thehydrostatic-and-hydrodynamic regime of the arrow 672. A dashed line 684represents the time at which the drill bit is brought back into contactwith the bottom of the wellbore, or pick up of WOB. After thedrillstring comes back into contact with the bottom, the RPM returns toa steady state value smaller than that off the off-bottom, fluid flowingregime as represented by an arrow 677.

FIGS. 7A, 7B, 7C, and 7D depict graphs corresponding to strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit during addition of a stand. FIG. 7A depicts agraph 700 displaying weight on bit (WOB) along y-axis 702 as a functionof time along x-axis 704. The graph 700 depicts as collected WOB valueswhich have not been adjusted, zeroed, or tared. During the standaddition, the WOB drops from a WOB associated with drilling (e.g., inthe tens of thousands of pounds) to a WOB associated with an off-bottomdrillstring. A point 706 corresponds to a sharp (i.e., nearly vertical)decrease in WOB consistent with a drillstring being pulled off-bottomduring a stand addition. A point 708 corresponds to an inflection pointin the WOB, where the decrease in WOB halts as a minimum or localminimum is reached. A point 710 corresponds to a second inflectionpoint, where WOB begins to increase as drilling fluid flow resumesduring the stand addition. The point 710 corresponds to the pumpsrestarting during the stand addition. Between the point 708 and thepoint 710, WOB maintains an approximately steady state value at thelocal minimum. This WOB value corresponds to those strain measurementswhich are used to determine hydrostatic pressure for the off-bottom, nofluid flow regime. An arrow 712 points to a sharply increasing portionof WOB. The WOB increases as the pumps ramp up due to a changing fluidflow and corresponding increase in hydrodynamic pressure. A point 714corresponds to full flow through the pumps of the drillstring—whichgenerates maximum fluid flow. A point 716 corresponds to the drillstringtagging the bottom of the wellbore, i.e., where the drillstring assumesWOB as the drill bit comes into contact with the bottom of the wellbore.After the point 716 WOB increases sharply (e.g., almost vertically) asWOB increases to a WOB associated with drilling.

FIG. 7B depicts a graph 730 displaying torque on bit (TOB) along y-axis732 as a function of time along x-axis 734. The graph 730 depicts ascollected TOB values which have not been adjusted. During the standaddition, the TOB drops from a TOB associated with drilling to a minimumTOB associated with an off-bottom drillstring. The minimum TOB can besubstantially zero or can be another local minimum. The minimum value ofTOB can vary based on sensor location, zeroing, calibration, etc. and ondrillstring conditions, such as minimum flow rate, clearance betweendrill bit and wellbore wall, etc. A point 736 corresponds to a decreasein TOB consistent with a drillstring being pulled off-bottom during astand addition. A point 736 corresponds to an inflection point whichoccurs as pumps (i.e., drill bit pumps and/or mud motor pumps) areturned off or otherwise ramped down. After the point 736, TOB decreasesrapidly towards a local minimum, reached at an inflection point 740where the drill bit is in slip (i.e., not engaged torsionally with thewellbore). The local minimum TOB value continues to a point indicated byan arrow 742. The arrow 742 corresponds to the restarting or ramping upoff the one or more pumps of the drillstring. The TOB value as the pumpsrestart remains at the local minimum, but variance within the TOB valuesincreases. A point 744 corresponds to the drillstring tagging the bottomof the wellbore, i.e., where the drillstring assumes WOB as the drillbit comes into contact with the bottom of the wellbore. From the point744, TOB increases to a steady state, reached at a point 746, which isthe TOB value associated with drilling.

FIG. 7C depicts a graph 760 displaying drill bit rotations per minute(RPM) along y-axis 762 as a function of time along x-axis 764. The graph760 depicts as collected RPM values which have not been adjusted. Duringthe stand addition, the RPM drops from an RPM associated with drillingto a minimum RPM associated with an off-bottom drillstring. The minimumRPM can be substantially zero or can be another local minimum. Theminimum value of RPM can vary based on sensor location, zeroing,calibration, etc. and on drillstring conditions, such as minimum flowrate, clearance between drill bit and wellbore wall, rotational frictionof the drill bit, etc. A peak 768 corresponds to an increase in RPMassociated with a drillstring being pulled off-bottom during a standaddition. The peak represents a faster rotation which occurs as WOB andTOB decrease when the drill bit disengages from the bottom of thewellbore. After the peak 768, RPM decreases as the pumps are turned offor ramped down until a minimum RPM is reached at an inflection point770. The minimum RPM continues until the pumps are restarted at aninflection point 772. Between the inflection point 770 and theinflection point 772, the RPM is substantially zero (in this case) orotherwise at a local minimum. After the inflection point 772, the RPMincreases steadily as the pumps are ramped up until the drillstring tagsthe bottom of the wellbore during the peak 774. The peak 774 in the RPMis an artifact of the measurement apparatus (e.g., sensor) for RPM anddoes not represent a physical jump in RPM as the drillstring tagsbottom. After the peak 774, RPM smooths out to a steady state valueassociated with drilling.

FIG. 7D depicts the graphs 700, 730, and 760 of FIG. 7A-7C respectively,on the same time axis (x-axis 790). A dashed line 780 indicates when thedrill bit is brought off-bottom as the stand addition begins. The RPM ofthe graph 760 spikes at the dashed line 780, where the increase in theapparent RPM is due to a decrease in the noise experienced by the RPMmeasurement collection system and not due to a decrease in RPM. A dashedline 782 indicates when the drill bit WOB, TOB, and RPM reach a minimumfor the off-bottom, no fluid flow portion of the stand addition. Betweenthe dashed line 780 and the dashed line 782, the drill bit rotationgradually stops as the mud pump slow to a stop which stops the rotationcaused by the positive displacement motor. The rotation of thedrillstring at the surface is also stopped. A dashed line 784 indicateswhen the mud pump begins pumping. A dashed line 786 indicates the startof surface rotation of the drillstring. A dashed line 788 indicates thatthe drill bit is on-bottom. The RPM decrease at the dashed line 788indicates a reduction in apparent RPM due to drilling noise.

FIGS. 8A, 8B, 8C, and 8D depict graphs corresponding to strainmeasurements, torque measurements, and rotational velocity measurementsacquired at a drill bit for multiple stand additions during drilling.FIG. 8A depicts a graph 800 displaying weight on bit (WOB) along y-axis802 as a function of time along x-axis 804. The graph 800 depicts ascollected WOB values which have not been adjusted for multiple standadditions and drilling events between those stand additions. Localmaximums 808 represent WOB measurements obtained during drilling. Localminimums 806 represent WOB measurements obtained during stand additions,while drilling is paused. Several local maximums and local minimums areidentified while others are not for graphical simplicity. The graph 800also displays local maximums 812, representing WOB measurements obtainedduring drilling, and local minimums 810, representing WOB measurementsobtained during stand additions while drilling in paused. The differencebetween the local maximums 808 and the local maximums 812 should beunderstood to correspond to different drilling modes. For example, thegreater WOB displayed during the local maximums 808 may correspond todrilling in a vertical wellbore while the WOB displayed during the localmaximums 812 may correspond to drilling in a lateral, horizontal, orotherwise nonvertical wellbore where WOB decreases due to directionalityof the wellbore.

FIG. 8B depicts a graph 830 displaying torque on bit (TOB) along y-axis832 as a function of time along x-axis 834. The graph 830 depicts ascollected TOB values which have not been adjusted for multiple standadditions and drilling events between those stand additions. Localminimums 836 represent TOB measurements obtained during stand additions,while drilling is paused. TOB values 838 represent TOB measurementduring drilling. An arrow 840 indicates a time point corresponding to achange in the drilling mode. After the arrow 840, TOB measurements aresignificantly zero or otherwise at a local minimum. Such a change may becaused by a change in drilling—such as a change from run in to run outwhere the drill bit does not experience significant torque as the drillbit is removed from the hole. Such a change can also correspond to achange or failure in a TOB sensor or other measurement acquiringapparatus.

FIG. 8C depicts a graph 860 displaying drill bit rotations per minute(RPM) along y-axis 862 as a function of time along x-axis 864. The graph860 depicts as collected RPM values which have not been significantlyadjusted for multiple stand additions and drilling events between thosestand additions. Local maximums 868 represent RPM measurements duringoff-bottom, fluid flowing portions of the stand addition. Local minimums867 represent RPM measurements during off-bottom, no fluid flow portionsof the stand addition—i.e., where RPM measurements are significantlyzero or reflect a local minimum. RPM values 866 represent RPMmeasurements during drilling. An arrow 870 indicates a time periodcorresponding to a change in the drilling mode. After the arrow 870,local minimums 874 correspond to RPM measurements while drilling ispaused. RPM values 872 represent RPM measurements during drilling orother drill bit rotation.

FIG. 8D depicts the graphs 800, 830, and 860 of FIG. 8A-8C respectively,on the same time axis (x-axis 890). The stand additions and stands ofthe drilling run produce synchronized responses in each of WOB, TOB, andRPM.

FIG. 9 depicts a schematic diagram of an example drilling system. InFIG. 9 a system 964 is formed from a portion of a drilling rig 902located at the surface 904 of a well 906. Drilling of oil and gas wellsis commonly carried out using a string of drill pipes connected togetherso as to form a drillstring 908 that is lowered through a rotary table910 into a wellbore or borehole 912. Here a drilling platform 986 isequipped with a derrick 988 that supports a hoist.

The drilling rig 902 may thus provide support for the drillstring 908.The drillstring 908 may operate to penetrate the rotary table 910 fordrilling the borehole 912 through subsurface formations 914. Thedrillstring 908 may include a kelly 916, drill pipe 918, and a bottomhole assembly 920A or 920B, perhaps located at the lower portion of thedrill pipe 918. Both a vertical and lateral portion of the borehole 912are depicted. It should be understood that drilling can take place at aninclination, including in a lateral borehole that trends upwards. Thedrillstring 908 may also include one or more centralizers 946 or otherstandoff devices. The one or more centralizer 946 may make intermittentor consistent contact with the borehole 912 as the drillstring 908 isadvanced through the subsurface formations 914.

The bottom hole assembly 920 may include drill collars 922, a down holetool 924, and a drill bit 926. The drill bit 926 may operate to create aborehole 912 by penetrating the surface 904 and subsurface formations914. The down hole tool 924 may comprise any of a number of differenttypes of tools including MWD tools, LWD tools, and others.

During drilling operations, the drillstring 908 (perhaps including theKelly 916, the drill pipe 918, and the bottom hole assembly 920) may berotated by the rotary table 910. In addition to, or alternatively, thebottom hole assembly 920 may also be rotated by a motor (e.g., a mudmotor) that is located down hole. Additionally, the mud motor may beused as a communication device, such as via frequency or amplitudemodulation, between the drill bit 926 and surface controller located atthe surface 904. The drill collars 922 may be used to add weight to thedrill bit 926. The drill collars 922 may also operate to stiffen thebottom hole assembly 920, allowing the bottom hole assembly 920 totransfer the added weight to the drill bit 926, and in turn, to assistthe drill bit 926 in penetrating the surface 904 and subsurfaceformations 914.

During drilling operations, a mud pump 932 may pump drilling fluid(sometimes known by those of ordinary skill in the art as “drillingmud”) from a mud pit 934 through a hose 936 into the drill pipe 918 anddown to the drill bit 926. The drilling fluid can flow out from thedrill bit 926 and be returned to the surface 904 through an annular area940 between the drill pipe 918 and the sides of the borehole 912. Thedrilling fluid may then be returned to the mud pit 934, where such fluidis filtered. In some embodiments, the drilling fluid can be used to coolthe drill bit 926, as well as to provide lubrication for the drill bit926 during drilling operations. Additionally, the drilling fluid may beused to remove subsurface formation 914 cuttings created by operatingthe drill bit 926.

As will be appreciated, aspects of the disclosure may be embodied as asystem, method or program code/instructions stored in one or moremachine-readable media. Accordingly, aspects may take the form ofhardware, software (including firmware, resident software, micro-code,etc.), or a combination of software and hardware aspects that may allgenerally be referred to herein as a “circuit,” “module” or “system.”The functionality presented as individual modules/units in the exampleillustrations can be organized differently in accordance with any one ofplatform (operating system and/or hardware), application ecosystem,interfaces, programmer preferences, programming language, administratorpreferences, etc.

Any combination of one or more machine readable medium(s) may beutilized. The machine-readable medium may be a machine-readable signalmedium or a machine-readable storage medium. A machine-readable storagemedium may be, for example, but not limited to, a system, apparatus, ordevice, that employs any one of or combination of electronic, magnetic,optical, electromagnetic, infrared, or semiconductor technology to storeprogram code. More specific examples (a non-exhaustive list) of themachine-readable storage medium would include the following: a portablecomputer diskette, a hard disk, a random-access memory (RAM), aread-only memory (ROM), an erasable programmable read-only memory (EPROMor Flash memory), a portable compact disc read-only memory (CD-ROM), anoptical storage device, a magnetic storage device, or any suitablecombination of the foregoing. In the context of this document, amachine-readable storage medium may be any tangible medium that cancontain, or store a program for use by or in connection with aninstruction execution system, apparatus, or device. A machine-readablestorage medium is not a machine-readable signal medium.

A machine-readable signal medium may include a propagated data signalwith machine readable program code embodied therein, for example, inbaseband or as part of a carrier wave. Such a propagated signal may takeany of a variety of forms, including, but not limited to,electro-magnetic, optical, or any suitable combination thereof. Amachine-readable signal medium may be any machine-readable medium thatis not a machine-readable storage medium and that can communicate,propagate, or transport a program for use by or in connection with aninstruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium may be transmittedusing any appropriate medium, including but not limited to wireless,wireline, optical fiber cable, RF, etc., or any suitable combination ofthe foregoing.

The program code/instructions may also be stored in a machine-readablemedium that can direct a machine to function in a particular manner,such that the instructions stored in the machine-readable medium producean article of manufacture including instructions which implement thefunction/act specified in the flowchart and/or block diagram block orblocks.

FIG. 10 depicts an example computer system with a pressure-effect offsetcalculator and a pressure-effect based strain error checker. Thecomputer system includes a processor 1001 (possibly including multipleprocessors, multiple cores, multiple nodes, and/or implementingmulti-threading, etc.). The computer system includes memory 1007. Thememory 1007 may be system memory or any one or more of the above alreadydescribed possible realizations of machine-readable media. The computersystem also includes a bus 1003 and a network interface 1005. The systemalso includes a pressure-effect offset calculator 1011, apressure-effect based strain error checker 1013. The pressure-effectoffset calculator 1011 determines a pressure-effect offset based on oneor more strain measurement. The pressure-effect based strain errorchecker 1013 checks the pressure-effect offset determined by thepressure-effect offset calculator 1011 for errors and, optionally, usesthe pressure-effect offset to monitor drilling behavior. Any one of thepreviously described functionalities may be partially (or entirely)implemented in hardware and/or on the processor 1001. For example, thefunctionality may be implemented with an application specific integratedcircuit, in logic implemented in the processor 1001, in a co-processoron a peripheral device or card, etc. Further, realizations may includefewer or additional components not illustrated in FIG. 10 (e.g., videocards, audio cards, additional network interfaces, peripheral devices,etc.). The processor 1001 and the network interface 1005 are coupled tothe bus 1003. Although illustrated as being coupled to the bus 1003, thememory 1007 may be coupled to the processor 1001.

While the aspects of the disclosure are described with reference tovarious implementations and exploitations, it will be understood thatthese aspects are illustrative and that the scope of the claims is notlimited to them. In general, techniques for strain measurement offset orzero-point calculations as described herein may be implemented withfacilities consistent with any hardware system or hardware systems. Manyvariations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations orstructures described herein as a single instance. Finally, boundariesbetween various components, operations and data stores are somewhatarbitrary, and particular operations are illustrated in the context ofspecific illustrative configurations. Other allocations of functionalityare envisioned and may fall within the scope of the disclosure. Ingeneral, structures and functionality presented as separate componentsin the example configurations may be implemented as a combined structureor component. Similarly, structures and functionality presented as asingle component may be implemented as separate components. These andother variations, modifications, additions, and improvements may fallwithin the scope of the disclosure.

Embodiment 1: A method comprising: obtaining strain measurements from astrain gauge at a first location associated with a drillstring, based ondetection of a pause in drilling; determining an offset valuecorresponding to a fluid pressure based on the strain measurements,wherein the offset value indicates contribution of fluid pressure to thestrain measurements and the fluid pressure comprises at least one ofhydrostatic pressure and hydrodynamic pressure; and indicating theoffset value for zeroing of the strain measurements.

Embodiment 2: The method of embodiment 1, wherein obtaining strainmeasurements from a strain gauge further comprises: determining if thedrillstring is off bottom; and selecting a subset of the strainmeasurements corresponding to the drillstring being off bottom, based ona determination that the drill string is off bottom, wherein determiningthe offset value comprises determining the offset value based on theselected subset of the strain measurements.

Embodiment 3: The method of embodiment 2, wherein determining that thedrillstring is off bottom comprises: obtaining weight on bitmeasurements and torque on bit measurements for a drill bit associatedwith the drillstring; determining if a local minimum in the weight onbit measurements occurs based on the weight on bit measurements;determining if the torque on bit measurements are substantially equal tozero; and determining that the drillstring is off bottom, based on thedetermination that there is a local minimum in the weight on bitmeasurements and that the torque on bit measurements are substantiallyequal to zero.

Embodiment 4: The method of embodiment 1 or 2, wherein obtaining strainmeasurements further comprises: determining that drilling fluid is notflowing; and selecting a subset of the strain measurements thatcorrespond to the drilling fluid not flowing, based on a determinationthat the drilling fluid is not flowing, wherein determining the offsetvalue comprises determining a hydrostatic offset value based on theselected subset of strain measurements.

Embodiment 5: The method of embodiment 4, wherein determining that thedrilling fluid is not flowing comprises: obtaining at least one ofrotational velocity measurements for a drill bit associated with thedrillstring and motor speed measurements for a drilling fluid pumpassociated with the drillstring; determining if the at least one of therotational velocity measurements for the drill bit and the motor speedmeasurements for the drilling fluid pump is substantially equal to zero;and determining that the drilling fluid is not flowing, based on adetermination that the at least one of the rotational velocitymeasurements for the drill bit and the motor speed measurements for thedrilling fluid pump is substantially equal to zero.

Embodiment 6: The method of embodiment 1 or 2, wherein obtaining strainmeasurements from a strain gauge further comprises: determining thatdrilling fluid is flowing; and selecting a subset of the strainmeasurements corresponding to the drilling fluid flowing, based on adetermination that the drilling fluid is flowing, wherein determiningthe offset value comprises determining a hydrodynamic offset value basedon the selected subset of the strain measurements.

Embodiment 7: The method of embodiment 6, wherein determining that thedrilling fluid is flowing comprises: obtaining at least one ofrotational velocity measurements for a drill bit associated with thedrillstring and motor speed measurements for a drilling fluid pumpassociated with the drillstring; determining if the at least one of therotational velocity measurements for the drill bit and the motor speedmeasurements for the drilling fluid pump is substantially not equal tozero; and determining that the drilling fluid is flowing, based on adetermination that the at least one of the rotational velocitymeasurements for the drill bit and the motor speed measurements for thedrilling fluid pump is substantially not equal to zero.

Embodiment 8: The method of any one of embodiments 1 to 7, whereindetection of the pause in drilling comprises at least one of detectionof an off-bottom event, detection of a stand addition, and detection ofan addition of a drillstring component.

Embodiment 9: The method of any one of embodiments 1 to 8, wherein thestrain measurements comprise at least one of axial strain measurementsand transverse strain measurements.

Embodiment 10: The method of any one of embodiments 1 to 9, whereindetermining an offset value comprises: determining a hydrostatic offsetvalue and a total offset value on the strain measurements; anddetermining a hydrodynamic offset value based, at least in part, on adifference between the total offset value and the hydrostatic offsetvalue.

Embodiment 11: The method of any one of embodiments 1 to 10, whereinindicating the offset value further comprises: determining if the offsetvalue is erroneous; indicating the offset value for zeroing of thestrain measurements, based on a determination that the offset value isnot erroneous; and indicating at least one previously determined offsetvalue for zeroing of the strain measurements, based on a determinationthat the offset value is erroneous.

Embodiment 12: The method of embodiment 11, wherein determining if theoffset value is erroneous comprises: determining a difference betweenthe offset value and the at least one previously determined offsetvalue; determining if the difference corresponds to an expected value ofthe difference between the offset value and the at least one previouslydetermined offset value; determining that the offset value is noterroneous, based on a determination that the difference does correspondto an expected value; and determining that the offset value iserroneous, based on a determination that the difference exceed theexpected value.

Embodiment 13: The method of embodiment 12, wherein determining if thedifference corresponds to an expected value of the difference furthercomprises determining the expected value of the difference between theoffset value and the at least one previously determined offset value.

Embodiment 14: A non-transitory, machine-readable medium havinginstructions stored thereon that are executable by a computing device toperform operations comprising instruction to: obtain strain measurementsfrom a strain gauge at a first location associated with a drillstring,based on detection of a pause in drilling; determine an offset valuecorresponding to a fluid pressure based on the strain measurements,wherein the offset value indicates contribution of fluid pressure to thestrain measurements and the fluid pressure comprises at least one ofhydrostatic pressure and hydrodynamic pressure; and indicate the offsetvalue for zeroing of the strain measurements.

Embodiment 15: The machine-readable medium of embodiment 14, whereininstructions to obtain strain measurements from a strain gauge compriseinstructions to: determine if the drillstring is off bottom; determinethat drilling fluid is not flowing; and select a subset of the strainmeasurements corresponding to the drillstring being off bottom anddrilling fluid not flowing, based on a determination that the drillstring is off bottom and that drilling fluid is not flowing, whereininstructions to determine the offset value comprises instructions todetermine a hydrostatic offset value based on the selected subset of thestrain measurements.

Embodiment 16: The machine-readable medium of embodiment 14 or 15,wherein instructions to obtain strain measurements from a strain gaugecomprise instruction to: determining if the drillstring is off bottom;determine that drilling fluid is flowing; and selecting a subset of thestrain measurements that correspond to the drillstring being off bottomand drilling fluid flowing, based on a determination that the drillstring is off bottom and that drilling fluid is flowing, whereininstruction to determining the offset comprises instruction to determinea hydrodynamic offset value based on the selected subset of the strainmeasurements.

Embodiment 17: The machine-readable medium of any one of embodiments 14to 16, further comprising instruction to: determine a difference betweenthe offset value and at least one previously determined offset value;determine if the difference corresponds to an expected value of thedifference between the offset value and the at least one previouslydetermined offset value; indicate the offset value for zeroing of thestrain measurements, based on a determination that the difference doescorrespond to an expected value; and indicate at least one of the atleast one previously determined offset value for zeroing of the straingauge, based on a determination that the difference exceed the expectedvalue.

Embodiment 18: An apparatus comprising: at least one strain gauge at afirst location associated with a drillstring; a processor; and acomputer-readable medium having instructions stored thereon that areexecutable by the processor to cause the apparatus to, obtain strainmeasurements from the at least one strain gauge, based on detection of apause in drilling; determine a offset value corresponding to a fluidpressure based on the strain measurements, wherein the offset valueindicates contribution of fluid pressure to the strain measurements andthe fluid pressure comprises at least one of hydrostatic pressure andhydrodynamic pressure; and indicate the offset value for zeroing of thestrain measurements.

Embodiment 19: The apparatus of embodiment 18, wherein the firstlocation is associated with a drill bit of the drillstring.

Embodiment 20: The apparatus of embodiment 18 or 19, further comprisinginstruction to: determine a difference between the offset value and atleast one previously determined offset value; determine if thedifference corresponds to an expected value of the difference betweenthe offset value and the at least one previously determined offsetvalue; indicate the offset value for zeroing of the strain measurements,based on a determination that the difference does correspond to anexpected value; and indicate at least one of the at least one previouslydetermined offset value for zeroing of the strain gauge, based on adetermination that the difference exceed the expected value.

Use of the phrase “at least one of” preceding a list with theconjunction “and” should not be treated as an exclusive list and shouldnot be construed as a list of categories with one item from eachcategory, unless specifically stated otherwise. A clause that recites“at least one of A, B, and C” can be infringed with only one of thelisted items, multiple of the listed items, and one or more of the itemsin the list and another item not listed.

1. A method comprising: obtaining strain measurements from a straingauge at a first location associated with a drillstring, based ondetection of a pause in drilling; determining an offset valuecorresponding to a fluid pressure based on the strain measurements,wherein the offset value indicates contribution of fluid pressure to thestrain measurements and the fluid pressure comprises at least one ofhydrostatic pressure and hydrodynamic pressure; and indicating theoffset value for zeroing of the strain measurements.
 2. The method ofclaim 1, wherein obtaining strain measurements from a strain gaugefurther comprises: determining if the drillstring is off bottom; andselecting a subset of the strain measurements corresponding to thedrillstring being off bottom, based on a determination that the drillstring is off bottom, wherein determining the offset value comprisesdetermining the offset value based on the selected subset of the strainmeasurements.
 3. The method of claim 2, wherein determining that thedrillstring is off bottom comprises: obtaining weight on bitmeasurements and torque on bit measurements for a drill bit associatedwith the drillstring; determining if a local minimum in the weight onbit measurements occurs based on the weight on bit measurements;determining if the torque on bit measurements are substantially equal tozero; and determining that the drillstring is off bottom, based on thedetermination that there is a local minimum in the weight on bitmeasurements and that the torque on bit measurements are substantiallyequal to zero.
 4. The method of claim 1, wherein obtaining strainmeasurements further comprises: determining that drilling fluid is notflowing; and selecting a subset of the strain measurements thatcorrespond to the drilling fluid not flowing, based on a determinationthat the drilling fluid is not flowing, wherein determining the offsetvalue comprises determining a hydrostatic offset value based on theselected subset of strain measurements.
 5. The method of claim 4,wherein determining that the drilling fluid is not flowing comprises:obtaining at least one of rotational velocity measurements for a drillbit associated with the drillstring and motor speed measurements for adrilling fluid pump associated with the drillstring; determining if theat least one of the rotational velocity measurements for the drill bitand the motor speed measurements for the drilling fluid pump issubstantially equal to zero; and determining that the drilling fluid isnot flowing, based on a determination that the at least one of therotational velocity measurements for the drill bit and the motor speedmeasurements for the drilling fluid pump is substantially equal to zero.6. The method of claim 1, wherein obtaining strain measurements from astrain gauge further comprises: determining that drilling fluid isflowing; and selecting a subset of the strain measurements correspondingto the drilling fluid flowing, based on a determination that thedrilling fluid is flowing, wherein determining the offset valuecomprises determining a hydrodynamic offset value based on the selectedsubset of the strain measurements.
 7. The method of claim 6, whereindetermining that the drilling fluid is flowing comprises: obtaining atleast one of rotational velocity measurements for a drill bit associatedwith the drillstring and motor speed measurements for a drilling fluidpump associated with the drillstring; determining if the at least one ofthe rotational velocity measurements for the drill bit and the motorspeed measurements for the drilling fluid pump is substantially notequal to zero; and determining that the drilling fluid is flowing, basedon a determination that the at least one of the rotational velocitymeasurements for the drill bit and the motor speed measurements for thedrilling fluid pump is substantially not equal to zero.
 8. The method ofclaim 1, wherein detection of the pause in drilling comprises at leastone of detection of an off-bottom event, detection of a stand addition,and detection of an addition of a drillstring component.
 9. The methodof claim 1, wherein the strain measurements comprise at least one ofaxial strain measurements and transverse strain measurements.
 10. Themethod of claim 1, wherein determining an offset value comprises:determining a hydrostatic offset value and a total offset value on thestrain measurements; and determining a hydrodynamic offset value based,at least in part, on a difference between the total offset value and thehydrostatic offset value.
 11. The method of claim 1, wherein indicatingthe offset value further comprises: determining if the offset value iserroneous; indicating the offset value for zeroing of the strainmeasurements, based on a determination that the offset value is noterroneous; and indicating at least one previously determined offsetvalue for zeroing of the strain measurements, based on a determinationthat the offset value is erroneous.
 12. The method of claim 11, whereindetermining if the offset value is erroneous comprises: determining adifference between the offset value and the at least one previouslydetermined offset value; determining if the difference corresponds to anexpected value of the difference between the offset value and the atleast one previously determined offset value; determining that theoffset value is not erroneous, based on a determination that thedifference does correspond to an expected value; and determining thatthe offset value is erroneous, based on a determination that thedifference exceed the expected value.
 13. The method of claim 12,wherein determining if the difference corresponds to an expected valueof the difference further comprises determining the expected value ofthe difference between the offset value and the at least one previouslydetermined offset value.
 14. A non-transitory, machine-readable mediumhaving instructions stored thereon that are executable by a computingdevice to perform operations comprising instruction to: obtain strainmeasurements from a strain gauge at a first location associated with adrillstring, based on detection of a pause in drilling; determine anoffset value corresponding to a fluid pressure based on the strainmeasurements, wherein the offset value indicates contribution of fluidpressure to the strain measurements and the fluid pressure comprises atleast one of hydrostatic pressure and hydrodynamic pressure; andindicate the offset value for zeroing of the strain measurements. 15.The machine-readable medium of claim 14, wherein instructions to obtainstrain measurements from a strain gauge comprise instructions to:determine if the drillstring is off bottom; determine that drillingfluid is not flowing; and select a subset of the strain measurementscorresponding to the drillstring being off bottom and drilling fluid notflowing, based on a determination that the drill string is off bottomand that drilling fluid is not flowing, wherein instructions todetermine the offset value comprises instructions to determine ahydrostatic offset value based on the selected subset of the strainmeasurements.
 16. The machine-readable medium of claim 14, whereininstructions to obtain strain measurements from a strain gauge compriseinstruction to: determining if the drillstring is off bottom; determinethat drilling fluid is flowing; and selecting a subset of the strainmeasurements that correspond to the drillstring being off bottom anddrilling fluid flowing, based on a determination that the drill stringis off bottom and that drilling fluid is flowing, wherein instruction todetermining the offset comprises instruction to determine a hydrodynamicoffset value based on the selected subset of the strain measurements.17. The machine-readable medium of claim 14, further comprisinginstruction to: determine a difference between the offset value and atleast one previously determined offset value; determine if thedifference corresponds to an expected value of the difference betweenthe offset value and the at least one previously determined offsetvalue; indicate the offset value for zeroing of the strain measurements,based on a determination that the difference does correspond to anexpected value; and indicate at least one of the at least one previouslydetermined offset value for zeroing of the strain gauge, based on adetermination that the difference exceed the expected value.
 18. Anapparatus comprising: at least one strain gauge at a first locationassociated with a drillstring; a processor; and a computer-readablemedium having instructions stored thereon that are executable by theprocessor to cause the apparatus to, obtain strain measurements from theat least one strain gauge, based on detection of a pause in drilling;determine a offset value corresponding to a fluid pressure based on thestrain measurements, wherein the offset value indicates contribution offluid pressure to the strain measurements and the fluid pressurecomprises at least one of hydrostatic pressure and hydrodynamicpressure; and indicate the offset value for zeroing of the strainmeasurements.
 19. The apparatus of claim 18, wherein the first locationis associated with a drill bit of the drillstring.
 20. The apparatus ofclaim 18, further comprising instruction to: determine a differencebetween the offset value and at least one previously determined offsetvalue; determine if the difference corresponds to an expected value ofthe difference between the offset value and the at least one previouslydetermined offset value; indicate the offset value for zeroing of thestrain measurements, based on a determination that the difference doescorrespond to an expected value; and indicate at least one of the atleast one previously determined offset value for zeroing of the straingauge, based on a determination that the difference exceed the expectedvalue.